NO20101003A1 - Elongated probe for wellbore tool - Google Patents

Abstract

Apparatus comprising a tool body configured for placement in a wellbore extended into an underground formation, an inflatable gasket connected to the tool body, and a measuring probe assembly coupled to the tool body and comprising an inner sealing member and an outer sealing member, wherein at least one of the inner sealing members and the sealing member comprises an elongated shape and wherein at least a portion of the measuring probe assembly is located on the inflatable packing.

Description

Extended measuring probe for well tools

Cross-reference to priority application

This application claims the benefits of and priority over Provisional US Patent Application No. 61/225,338, filed July 14, 2009, which is hereby incorporated by reference in its entirety.

Background for the publication

Well drills are drilled into the earth's crust to retrieve deposited hydrocarbons and other desirable material that is buried in the formations. Typically, a well is drilled by connecting a drill bit to the lower end of a series of linked cylinder drill sections, known as a drill rod. Drilling fluids, or drilling mud, are pumped down through a central drill in the drill rod and exit through ports that are places on the drill bit. The drilling mud acts to lubricate and cool the drill bit, to carry samples along back to the surface and to establish sufficient hydrostatic "head" to prevent the fluids from "blowing out" the wellbore as soon as they are reached.

To sample and test fluids, such as deposits of hydrocarbons and other desired materials embedded in the formations, a formation probe or tester is typically used in the well drilled through the formations. Various formation fluid testers for well cable and/or logging downhole tools are known in the art, such as those described in US Patent Nos. 4,860,581, 4,936,139 and 7,458,419. These patents are hereby incorporated in their entirety herein by reference.

Such formation fluid testers may include and use a focused probe apparatus, as shown in fig. 1.1 fig. 1, an apparatus 101 is shown, which includes first a sealing member 111 and a second sealing member 121. The sealing members 111 and 121 are two round concentric sealing members, in which the sealing member 111 is referred to as the "inner packing plug" and the sealing member 121 is referred to as the " outer packing plug". The area within sealing element 111 is defined as a trial flow path 113, and the area between sealing element 111 and sealing element 121 is defined as a protective flow path 123. The outer diameter of sealing element 121 may be approximately 12.1 cm (4.75 inches).

During a test operation, apparatus 101 will be pressed against the wall of the interesting subterranean formations. Fluid can then be withdrawn from the formation through apparatus 101, via sample flow path 113 and protection flow path 123. Due to the flow dynamics in the formation, fluid drawn into and flowing through sample flow path 113 tends to be less contaminated, such as containing less drilling mud filtrate, to comparison with fluid that is drawn into and flows through the protective flow path 123. The apparatus 101 shown in Figure 1 may be suitable during sampling in formations that have medium to high mobility, but may be less effective in formations with low mobility.

Brief description of the drawings

This disclosure is best understood from the following detailed descriptions, when read in conjunction with the accompanying illustrations. It is emphasized that in accordance with standard practice in the industry, various features are not drawn to scale. The dimensions of the various functions can be increased or decreased as desired, for clarity in the discussion of them.

Figure 1 is a schematic representation of known apparatus

Figure 2 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 3 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 4 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 5 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 6 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 7 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 8 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figures 9A and 9B are schematic representations of apparatus according to one or more aspects of the present disclosure. Figures 10A and 10B are schematic representations of apparatus according to one or more aspects of the present disclosure. Figures 1 IA and 1 IB are schematic representations of apparatus according to one or more aspects of this disclosure. Figure 12 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 13 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 14 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 15 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 16 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 17 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 18 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 19 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 20 is a schematic representation of apparatus according to one or more aspects of this disclosure. Figure 21 is a schematic representation of apparatus according to one or more aspects of this disclosure.

Detailed description

It is to be understood that the following disclosure makes possible many different designs, or examples, for the realization of different functions of different designs. Certain examples of components and arrangements are described below, in order to facilitate this disclosure. These are of course only examples, and are not intended to be limiting. In addition, this disclosure may repeat reference numbers and/or letters in the various examples. This repetition is intended to simplify and clarify the presentation and does not in itself determine the relationship between the various designs and/or configurations discussed. In addition, the formation of a first feature over or on a second feature in the description that follows may include designs in which the first and second features are formed in direct contact, and may also include designs in which additional features may be formed in between the first and second function, so that the first and second functions are no longer in direct contact.

According to one or more aspects of the present disclosure, there may be provided an apparatus that can be used in sampling and/or testing operations. The apparatus may include a tool body and a measuring probe assembly movably mounted on the tool body. The tool can be part of a well tool. The well tool may be attached to a tool rod and may be used in a well environment. For example, the tool can be placed in a wellbore, formed within and extending into the underground formation. The measuring probe assembly of the apparatus may include an inner sealing element and an outer sealing element. The inner sealing element may be located within the outer sealing element. The inner sealing element and/or the outer sealing element may have an "oblong shape". As used herein, an elongated shape of a sealing element may refer to a shape that may have different dimensions between the length of the sealing element and the width of the sealing element. For example, the sealing element can have an elongated shape by having a greater length of the sealing element than the width of the sealing element.

The apparatus may include a sample flow inlet configured to receive fluid from within the inner seal member and may include a protective flow inlet configured to receive fluids from within the inner seal member and the outer seal member. A flow line can then be connected to the sample flow inlet to allow the liquid from the sample flow inlet to flow therethrough, and another flow line can be connected to the protection flow inlet to allow the liquid from the protection flow inlet to flow therethrough.

The inner sealing element and the outer sealing element of the measuring probe assembly can be movable with respect to each other. For example, the inner sealing element may be located on an inner plate and the outer sealing element may be located on an outer plate, in which the inner plate and the outer plate are movable with respect to each other.

With reference to Figure 2, a schematic representation of an apparatus 201 is presented in accordance with one or more aspects of the present disclosure. The apparatus 201 includes an inner sealing element 211 and an outer sealing element 221. The inner sealing element 211 is located within and/or surrounded by the outer sealing element 221. The inner sealing element 211 may define a test flow path 213 within the area of the inner sealing element 211, in which liquid can be drawn in and through a sample flow inlet connected to the sample flow path 213. The outer sealing element 221 and the inner sealing element 211, into which liquid can be drawn into and through the protective flow inlet, are fluid connected to the protective flow path 223.

The inner sealing element 211 and/or the outer sealing element 221 can have an elongated shape. For example, as shown in Figure 2, the outer sealing element 221 can have an elongated shape with a length LG and width Woi, which length L0 can be significantly greater than width Wo. For example, the length Lo of the outer sealing member 221 may be approximately 25.4 cm (about 10 inches) and the width Wo of the outer sealing member 221 may be approximately 12.1 cm (4.75 inches). However, those of ordinary skill in the art will understand that the dimensions of the sealing elements in this disclosure are not so limited and that other dimensions may be used within the scope of this disclosure.

With reference to Figure 3, a schematic representation of an apparatus 301 is presented in accordance with one or more aspects of the present disclosure. Similar to Figure 2, the apparatus 301 includes an inner sealing element 311 and an outer sealing element 321, in which the inner sealing element 311 may define a test flow path 313 and the outer sealing element 321 may define a protective flow path 323. In addition to the outer sealing element 321, the inner the sealing element 311 has an elongated shape. For example, the inner sealing element 311 may have a length Li and a width Wi, in which length Li may be significantly greater than width Wi. For example, the length Li of the inner sealing member 311 may be approximately 17.8 to 20.3 cm (7-8 inches) and the width Wi of the inner sealing member 311 may be approximately 7.6 cm (3 inches).

With reference to Figure 4, a schematic representation of an apparatus 401 is presented in accordance with one or more aspects of the present disclosure. The apparatus 401 includes an inner sealing element 411 and an outer sealing element 421, in which the inner sealing element 411 can define a test flow path 413 and the outer sealing element 421 can define a protective flow path 423. The inner sealing element 411 and the outer sealing element 421 can have an elongated shape. The outer sealing element 421 can have a length that is approximately twice the length of the outer sealing elements 221 and 321 shown in Figures 2 and 3. These dimensions make it possible to allow the protective flow path 423 to be significantly larger than the protective flow paths 223 and 323, respectively, shown in Figures 2 and 3. The inner sealing element 411 may have essentially the same shape as the inner sealing elements 211 and 311 shown in Figures 2 and 3 respectively. The inner sealing element 411 and/or the outer sealing element 421 may, however, have other shapes, sizes and/or dimensions, so that the sealing elements have an elongated shape within the scope of this disclosure.

With reference to Figure 5, a schematic representation of an apparatus 501 is presented in accordance with one or more aspects of the present disclosure. The apparatus 501 includes an inner sealing element 511 and an outer sealing element 521, in which the inner sealing element 511 can define a test flow path 513 and the outer sealing element 521 can define a protective flow path 523. The inner sealing element 511 and the outer sealing element 521 each have an elongated shape. The outer sealing element 521 may be essentially the same as the outer sealing element 421 shown in Figure 4, while the inner sealing element 511 may have a length which is approximately twice the length of the inner sealing elements 311 and 411 shown in Figures 3 and 4 respectively. These the dimensions can enable a significantly larger sample flow path 513 than the sample flow paths shown in figures 2, 3 and 4.

With reference to Figure 6, a schematic representation of an apparatus 601 is presented in accordance with one or more aspects of the present disclosure. The apparatus 601 may include an inner sealing element 611 and an outer sealing element 621, in which the inner sealing element 611 may define a test flow path 613 and the outer sealing element 621 may define a protective flow path 623. The inner sealing element 611 and the outer sealing element 621 have an elongated shape. One or more of the inner and/or outer corner radii of the inner sealing element 611 and/or the outer sealing element 621 may be significantly larger than the corner radius shown in Figure 3. For example, one or more of the corner radii of the inner sealing element 611 and the outer the sealing member 621 may be 6.35 mm (0.25 inch) or larger. Such large corner radii can give the inner sealing element 611 and the outer sealing element 621 a more oval shape, compared to Figure 3. One or more corner radii in the inner sealing element 611 and/or the outer sealing element 721 can be a full radius, or alternatively have a significant less or no radius, so that one or more corners of the inner sealing element and/or the outer sealing element may be substantially square.

With reference to Figure 7, a schematic representation of an apparatus 701 is presented in accordance with one or more aspects of the present disclosure. The device 701 can be identical or essentially similar to one or more devices shown in Figures 2-6. For example, apparatus 701 includes an inner seal member 711 and an outer seal member 721, in which the inner seal member 711 may define a test flow path 713 and the outer seal member 721 may define a guard flow path 723. The inner seal member 711 and the outer seal member 721 each have an oblong shape.

The inner sealing element 711 and/or the outer sealing element 721 may also be located on a plate or other support 731. The support 731 may also include a bracket and/or

other structure on which the inner sealing element 711 and/or the outer sealing element 721 can be placed. The inner and outer sealing members 711 and 721, respectively, can be connected to the support 731 by mechanical fasteners, adhesive means and/or other methods. For example, one or both of the sealing elements 711 and 721 may be shaped (eg, by injection molding) to the edges and/or devices in the support 731.

The support 731 may be used to provide structure and/or support to the inner seal member 711 and/or the outer seal member 721. As such, the support 731 may be formed from and/or include a metal, such as steel and/or any other rigid material . Alternatively, the support 731 can be formed from and/or include less rigid materials and/or non-rigid materials, such as a malleable and/or bendable material. The support 731 can also be selectively and/or partially inflatable, so that the support 731 can be moved. The inner sealing member 711 and/or the outer sealing member 721 may be formed from and/or include a sealing material, such as an elastomeric material. The inner sealing element 711 and the outer sealing element 721 can also have substantially the same height, as shown in Figure 7. However, other shapes, sizes and/or dimensions are also within the scope of this disclosure. With reference to Figure 8, a schematic representation of an apparatus 801 is presented in accordance with one or more aspects of the present disclosure. The device 801 may be identical or substantially similar to one or more devices shown in Figures 2-6. For example, apparatus 801 includes an inner seal member 811 and an outer seal member 821, in which the inner seal member 811 may define a sample flow path 813 and the outer seal member 821 may define a guard flow path 823. The inner seal member 811 and the outer seal member 821 may have an elongated shape. The inner sealing element 811 and the outer sealing element 821 can also be placed on a support 831. The support 831 can be essentially similar or identical to the support 731 shown in Figure 7.

As shown, one or more surfaces (eg, sealing surfaces) of the inner sealing element 811 and/or the outer sealing element 821 may be rounded or cylindrical. For example, in Figure 8, the upper surface (relative to the support 831) of the inner sealing member 811 and the outer sealing member 821 is rounded. This arrangement enables connection between apparatus 801 and the wall of a wellbore inside an underground formation. For example, as the wall of the wellbore may be rounded and/or have a radius or curve, the inner seal member 811 and the outer seal member 821 may be rounded to at least partially conform to the shape of the wellbore. The upper surfaces of the inner sealing element and the outer sealing element may correspond to substantially identical cylinders and/or have substantially the same radius of curvature as shown in Figure 8, and/or may have varying and/or different radius or curvature. The radius and curvature may be essentially the same as or less than the radius of the well in which use of apparatus 801 is considered.

Referring to Figures 9A and 9B, schematic representations of an apparatus 901 in accordance with one or more aspects of the present disclosure are presented. The device 701 can be identical or essentially similar to one or more devices shown in Figures 2-6. For example, apparatus 901 includes an inner seal member 911 and an outer seal member 921, in which the inner seal member 911 may define a test flow path 913 and the outer seal member 921 may define a guard flow path 923. The inner seal member 911 and the outer seal member 921 may have an elongated shape. As shown, the inner seal member 911 may be located on an inner support 931 and the outer seal member may be located on an outer support 933. The inner support 931 is located within and/or encapsulated by the outer support 933. The inner or outer support , respectively 931 and 933, may be substantially similar to the support 731 shown in figure 7, with the following exception.

The inner seal member 911 may be movable with respect to the outer seal member 921. A control member may be connected to the inner support 931 and configured to move the inner support 931 relative to the outer support 933 and/or the well tool to which the apparatus 901 is connected . Additionally or alternatively, a control element may be connected to the outer support 933 and configured to move the outer support 933 relative to the inner support 931 and/or the well tool to which the apparatus 901 is connected. Such control elements can include hydraulic control elements, mechanical control elements, electrical control elements and others.

The inner support 931 and the inner sealing member 911 placed thereon can be moved independently of the outer support 933 and the outer sealing member 921 placed thereon. This arrangement may improve the ability of the inner seal member 911 and/or the outer seal member 921 to seal in the joint in the subterranean formation. For example, the inner seal member 911 may be subjected to forces through the inner support 931, and the outer seal member 921 may be subjected to forces through the outer support 933, in which cases these forces may be the same or different in amount and may be applied simultaneously, in series or otherwise.

The inner sealing member 911 and the outer sealing member 921 may have significantly different heights, as shown in Figures 9A and 9B. For example, the inner sealing element 911 can have a significantly smaller height than the outer sealing element 921. However, the inner sealing element 911 can alternatively have a significantly greater height than the outer sealing element 921, or have the same height as the outer sealing element 921.

Referring to Figures 10A and 10B, various schematic representations of an apparatus in accordance with one or more aspects of the present disclosure are presented. In particular, Figure 10A shows a top schematic representation of well tool 1051, with an apparatus 1061 formed through it and Figure 10B shows a side schematic representation of a measuring probe assembly 1071.

In Figure 1 OA, the well tool 1051 includes a tool body 1053 configured for use in a well drilling environment. The tool body 1053 can be essentially cylindrical. The apparatus 1061 can be formed within the well tool 1051 so that the control unit 1061 can move mainly through the tool body 1051.

The well tool 1051 may have one or more flow lines extending through it. For example, as shown in Figure 10A, the tool body 1053 may have one or more flow lines 1055 formed therethrough. One or more of the flow lines 1055 can be configured to transport fluid, such as fluid that has been retrieved using the probe assembly 1071, into and through the well tool 1051. For example, fluid that has been retrieved using the well tool 1055 can be transported to one or more collection bottles and/or well drills using the flow lines 1055. The tool body 1053 may also include one or more hydraulic lines 1057 formed therethrough. The one or more hydraulic lines 1057 may be used to actuate one or more components of the well tool 1051, such as to actuate one or more control units 1063 (eg, pistons), which may be fluidly connected to the hydraulic lines 1057. The tool body 1053 may also include one or more electrical leads 1059 formed therethrough. The one or more electrical wires 1059 may also be used inside the well tool 1051 to transmit electrical current and/or signals.

In Figure 10B, the measuring probe assembly 1071 is shown. The measuring probe assembly 1071 can be movably located within apparatus 1061 in the well tool 1051. The measuring probe assembly 1071 can include a support 1031, such as a plate, on which the sealing elements (not shown) can be placed. The measuring probe assembly 1071 may be movably attached to the tool body 1053, such as by attaching the control units 1063 to the support 1031 of the measuring probe assembly 1071. As such, the measuring probe assembly 1071 and the sealing elements included therewith may be able to move with respect to the tool body 1053. During movement, the measuring probe assembly 1071 can thus be selectively disposed within and in the extension of the apparatus 1061 on the tool body 1053. The sealing elements placed on the support 1031 can be substantially similar or identical to one or more of the sealing elements shown in Figures 2-6, among other such sealing elements within the scope of this disclosure . The support 1031 may be substantially similar or identical to the support 731 shown in Figure 7, among other such supports within the scope of this disclosure.

The measuring probe assembly 1071 may have one or more flow lines 1073 formed therethrough, such as to transport liquids taken up through the measuring probe assembly 1071 and may also have one or more hydraulic lines 1075 formed therethrough, such as to activate one or more components of the measuring probe assembly 1071. The flow lines 1073 to the measuring probe assembly 1071 can then be fluidly coupled to flow line 1055 on the tool body 1053 and the hydraulic lines 1075 on the measuring probe assembly 1071 can be fluidly coupled to the hydraulic lines 1057 on the tool body 1053. As such, one or more devices shown in Figure 2-9B can be included within the tool body and the measuring probe assembly, as shown in Figures 10A and 10B.

With reference to Figures 1 IA, 1 IB and 11C, various schematic representations of an apparatus in accordance with one or more aspects of the present disclosure are presented. Specifically, Figure 1 IA shows a top view of a well tool 1151 having an apparatus 1161 formed therein. Figure 1 IB shows a cross-section of the well tool 1151 and Figure 11C shows the well tool 1151 in perspective with the measuring probe assembly 1171.

The well tool 1151 includes a tool body 1153, in which the tool body 1153 can be used within a well environment, such as located within a wellbore extending into a subterranean formation. As such, the tool body 1153 may be substantially cylindrical. The apparatus 1161 may be shaped within the well tool 1151 so that the apparatus 1161 extends into the tool body 1151. Instead of the apparatus extending through the tool body, the apparatus 1161 only partially extends into the tool body 1151.

The well tool 1151 may have one or more lines extending therethrough. For example, as shown in Figure 1 IB, the tool body 1153 may have one or more flow lines 1155 formed therethrough, may have one or more hydraulic lines 1157 formed therethrough, and/or may have one or more electrical lines 1159 formed therethrough. The one or more hydraulic lines 1157 may be used within the well tool 1151 to activate one or more components of the well tool 1151, such as to activate one or more control units 1163 (eg, pistons), which may be fluidly connected to the hydraulic lines 1157 .

In Figure 11C, the measuring probe assembly 1171 is shown. The measuring probe assembly 1171 can be located, such as movably located, within the apparatus 1161 in the well tool 1151. The measuring probe assembly 1171 can include a support 1131, in which an elongated test flow path 1111 and an elongated protection flow path 1121 are manufactured. The support 1131, the test flow path 1111 and the protection flow path 1121 may be substantially similar, or have one or more similar aspects, relative to those shown in the preceding figures and/or described above. For example, the sample flow path 1111 and the protection flow path 1121 may be at least partially defined by sealing elements that may be located on the support 1131. The support 1131 may be cylindrical in shape, at least in part, to help conform to the shape of the wellbore wall. The measuring probe assembly 1171 may be movably attached to the tool body 1153, such as by attaching the control units 1163 to the support 1131 of the measuring probe assembly 1171. As such, the measuring probe assembly 1171 and the test flow path 1111 and the guard flow path 1121 included therein may be able to move with respect to the tool body 1153 During movement, the measuring probe assembly 1171 will thus be selectively disposed within and in the extension of apparatus 1161 on the tool body 1153.

Although only two control units 1163 are shown in Figure 1 IA, a single control unit or more than two control units may alternatively be used within the scope of this disclosure. One or more of the control units 1163 can be fixed when attached to the support 1131 on the measuring probe assembly 1131. Alternatively, one or more of the control units 1163 can be rotatably attached to the support 1131, such as rotationally attached (e.g. ball joints) at the connection point between the control units 1163 and the support 1131 This arrangement can improve the coupling capability of the probe assembly 1171, including the sealing elements, such as by creating a sealing connection with the subterranean formation and/or wellbore wall.

Referring to Figure 12, a cross-section of a measurement probe assembly 1271 is presented in accordance with one or more aspects of the present disclosure. The measuring probe assembly 1271 may be substantially similar to, or have one or more similar aspects relative to one or more of the measuring probe apparatus shown in the preceding figures and/or discussed above. For example, the measurement probe assembly 1271 may include an inner seal member 1211 and an outer seal member 1221, in which the inner seal member 1211 may at least partially define a sample flow path 1213 and the outer seal member 1221 may at least partially define a guard flow path 1223. The inner seal member 1211 and the outer sealing element 1221 may also have an elongated shape. The inner sealing element 1211 may be placed on an inner support 1231 and the outer sealing element 1221 may be placed on an outer support 1233. The inner support 1231 and/or the outer support 1233 may be plates, such as plates having an elongated shape and /or as otherwise described above with regard to the preceding figures.

The measuring probe assembly 1271 can have one or more control units connected thereto. For example, as shown in Figure 12, one or more control units 1263, such as plungers, may be connected and attached to the probe assembly 1271. The control units 1263 may be used to removably attach the probe assembly 1271 to a tool body, such as by attaching the control units 1263 to the the outer support 1233.

The measuring probe assembly 1271 may have one or more lines extending through it. The measuring probe assembly 1271 may have one or more hydraulic lines 1275 formed therethrough, such as to actuate one or more components of the measuring probe assembly. For example, the hydraulic lines 1275 may be fluidly connected to one or more control units within the probe assembly 1271. As shown, in one aspect, the probe assembly 1271 may include a control unit 1281, such as a piston, which is attached to the inner support 1231 in which control unit 1281 may be fluidly connected to and actuated by the hydraulic lines 1275. As fluid flows through the hydraulic lines 1275 into the cavities within the probe assembly 1271 adjacent the control unit 1281, the control unit 1281 may respond to the fluid pressure from the hydraulic lines 1275 by moving, thereby moving the the inner support 1231 attached to the control unit 1281. The inner sealing element 1211 placed on the inner support 1231 can also move with the inner support 1231, thus enabling the inner sealing element 1211 to move with respect to the outer sealing element 1221. This the event can improve the possibility that it in dre the sealing element 1211 and/or the outer sealing element 1221 are interconnected, as in sealing interconnection, inside the underground formation. For example, the inner seal member 1211 may be subjected to forces through the inner support 1231, and the outer seal member 1221 may be subjected to forces through the outer support 1233, in which cases these forces may be the same or different in amount, as desired.

As shown, the measuring probe assembly 1271 may include a control assembly 1283, such as a piston, which is positioned adjacent to and fluidly connected to an inlet of the sample flow path 1213. As such, as fluid flows through the hydraulic lines 1275 into the cavities within the measuring probe assembly 1271 adjacent the control assembly 1283 , the control unit 1283 can respond to the flow pressure from the hydraulic lines 1275 by moving, thereby opening and closing the inlet to the sample flow path 1213. The measuring probe assembly 1271 can include a filter 1285, such as by having the filter 1285 located adjacent to the inlet to the sample flow path 1213 .As liquid enters through the sample flow path 1213, liquid may accordingly pass through the filter 1285, such as to remove particles and/or solids from the liquid entering through the sample flow path 1213.

The measurement probe assembly 1271 may have one or more flow lines 1273 formed therethrough, such as to transport fluids taken up by the measurement probe assembly 1271. For example, as shown, the measurement probe assembly 1271 may include one or more flow lines 1273A fluidly coupled to the inlet of the sample flow path 1213. As such, as liquid flows into and through the sample flow path 1213, the liquid may be transported away through flow line 1273A fluidly coupled to the sample flow path 1213. Similarly, measurement probe assembly 1271 may include one or more flow lines 1273B fluidly coupled to one or more inlets in the guard flow path 1223. As such, as liquid flows into in and through the liquid flow path 1223, the liquid can be transported away through flow line 1273B, fluidly connected to the protective flow path 1223.

As discussed above, fluid drawn into and flowing through sample flow path 1213 may be less contaminated, compared to fluid drawn into and flowing through containment flow path 1223. Fluid from sample flow path 1213 may be directed to flow to one or more sample chambers, sample bottles and/or boreholes, outside the well for testing. Liquid from the protective flow path 1223 can be controlled to flow back to the wellbore, as this liquid is probably less interesting for sampling and/or testing. However, those of ordinary skill in the art will appreciate that the present disclosure is not so limited, as both or neither of the flow paths or flow lines fluidly connected thereto can be used for sampling and/or testing.

One or more sealing element supports may be included in the sealing elements. For example, as shown in Figure 12, an inner seal member support 1215 may be located adjacent to the inner seal member 1213, and/or an outer seal member support 1225 may be located adjacent to the outer seal member 1223. The seal member supports 1215 and 1225 may be used to support seal member 1213, respectively. and 1223. As such, the sealing element supports 1215 and 1225 may be formed of and/or include a rigid and/or non-rigid material. For example, the sealing element supports 1215 and 1225 can prevent protrusion and/or deformation of the sealing elements 1213 and 1223, such as during testing and/or sampling with the measuring probe assembly 1271, thereby improving the reliability and sealing ability of the measuring probe assembly 1271.

One or more sealing elements may be located within the measuring probe assembly 1271, such as to prevent leakage within the measuring probe assembly 1271. For example, as shown in Figure 12, one or more sealing elements 1291, such as o-rings, may be located adjacent to one or more such moving components of the measuring probe assembly 1271, such as the adjacent control units 1281 and 1283. As such, the sealing elements 1291 can be used to prevent leakage within and adjacent to the control units 1281 and 1283.

One or more keys may be located within and/or included within the probe assembly. For example, as shown in Figure 12, one or more keys 1293 may be included in the measuring probe assembly 1271, such as located adjacent to and/or placed on one or more of the movable components of the measuring probe assembly 1271. As such, the keys 1293 may be used to prevent rotation of one movable component with respect to one other adjacent component.

One or more valves may be located inside and/or fluidly connected to the measuring probe assembly 1271. For example, a valve, such as a sequence valve, may be fluidly connected to one or more of the flow lines and/or hydraulic lines in the measuring probe assembly. By having a sequence valve fluidly connected to the measuring probe assembly, the sequence valve can control the sequence of the movements and/or actions of the measuring probe assembly. For example, a sequence valve can be used to move control unit 1281 ahead of control unit 1283, or vice versa. Accordingly, one or more valves may be included inside and/or fluidly connected to the measuring probe assembly.

Referring to Figure 13, a cross-section of a measurement probe assembly 1371 is presented in accordance with one or more aspects of the present disclosure. The measuring probe assembly 1371 may be substantially similar to, or have one or more similar aspects relative to, the apparatus shown in the preceding figures and/or described above. For example, the measurement probe assembly 1371 may include an inner seal member 1311 and an outer seal member 1321, in which the inner seal member 1311 may at least partially define a sample flow path 1313 and the outer seal member 1321 may at least partially define a guard flow path 1323. The sample flow path 1313 and/or or the protective flow path 1323 can have an elongated shape. The inner sealing element 1311 and/or the outer sealing element 1321 can also have an elongated shape. The inner seal member 1311 may be located on an inner support 1331, and the outer seal member 1321 may be located on an outer support 1333. The inner and outer supports, 1331 and 1333, may be substantially similar to those shown in Figures 9A and 9B. For example, the inner support 1331 and/or the outer support 1333 may be plates, such as plates having an elongated shape.

One or more control units 1363, such as pistons, may be connected to and attached to the measuring probe assembly 1371. In particular, the control units 1363 may be used to movably attach the measuring probe assembly 1371 to a tool body, such as by attaching the control units 1363 to the outer support 1333. sealing element support 1315 can be placed adjacent to the inner sealing element 1313, and/or an outer sealing element support 1325 can be placed adjacent to the outer sealing element 1323. The sealing element supports 1315 and 1325 can also make it possible to have an opening and/or a space adjacent to the sealing elements 1313 and 1323, to enable movement and/or deformation of the sealing elements 1313 and 1323. The measuring probe assembly 1371 may include one or more flow lines 1374A fluidly connected to the inlet of the test flow path 1313, and may also include one or more flow lines 1373B fluidly connected to one or more inlets of the protection flow path 1323.

One or more sealing elements herein may be formed from and/or include sealing material, such as a pliable material, which may include silicone rubber, a fluoroelastomer (FKM) rubber (such as provided by FKM Viton®) or copolymer rubber (such as FEPM, provided by AFLAS®). One or more sealing element supports of the present disclosure may be formed from and/or include hydrogenated nitrile butadiene rubber (hnbr), polyether ether ketone (PEEK), as well as compositions having, for example, metallic reinforcements.

Referring to Figure 14, a cross-section of an apparatus in accordance with one or more aspects of the present disclosure is presented. A well tool 1451 may be provided, with a probe assembly 1471 movably attached thereto, in which the probe assembly 1471 may be movably attached with a gasket 1495, such as an inflatable gasket. The well tool 1451 includes a tool body 1453, in which the tool body 1453 can be used within a well environment, such as located within a well extending into an underground formation.

The well tool 1451 may have one or more lines extending through it. For example, as shown in Figure 14, the tool body 1453 may have one or more flow lines 1455 formed therethrough, and/or may have one or more hydraulic lines 1457 formed therethrough. The one or more hydraulic lines 1457 may be used within the well tool 1451 to activate one or more components of the well tool 1451, such as to activate and/or inflate the packing 1495, which may be fluidly connected to the hydraulic lines 1457.

The measuring probe assembly 1471 may include a support 1431, in which an internal sealing element

1411 and/or an outer sealing element 1421 may be located on the support 1431. For example, in Figure 14, the support 1431 may have only the inner sealing element 1411 located on the support 1431, in which the outer sealing element 1421 may be located on the gasket 1495. As such that the measuring probe assembly 1471, and the inner sealing element 1411 and the outer sealing element 1421 included therein, may be movable with respect to the tool body 1453, such as when the gasket 1495 is inflated. This arrangement may improve the ability of the probe assembly 1471, including the inner seal member 1411 and/or the outer seal member 1421, to couple with, as in a sealing interconnect, the subterranean formation.

Referring to Figure 15, a top view of a measurement probe assembly 1571 in accordance with one or more aspects of the present disclosure is presented. The measuring probe assembly 1571 may be substantially similar to, or have one or more similar aspects relative to, the apparatus shown in the preceding figures and/or described above. For example, measurement probe assembly 1571 may include an inner seal member 1511 and an outer seal member 1521, in which the inner seal member 1511 may define a sample flow path 1513 and the outer seal member 1521 may define a guard flow path 1523. The inner seal member 1511 and the outer seal member 1521 may have an elongated shape. The sample flow path 1513 and/or the protection flow path 1523 can also have an elongated shape. The inner sealing element 1511 may also be located on an inner support 1531, and the outer sealing element 1521 may be located on an outer support 1533. For example, the inner support 1531 may be located at least partially above the outer support 1533. Alternatively, the inner support 1531 be located within and/or enclosed in the outer support 1533. The inner support 1531 and/or the outer support 1533 may have an elongated shape. The inner support 1531 can slide with respect to or in extension of the outer support 1533.

The measuring probe assembly 1571 may include one or more inlets for the test flow path and/or the protection flow path. For example, as shown in Figure 15, the sample flow path 1513 may have an inlet 1517, in which a flow line may be fluidly connected to the inlet 1517. The inlet 1517 may then be selectively opened and closed, such as by one or more control units. As shown in Figure 15, the inlet 1517 can have a substantially circular shape. However, the inlet may have other shapes in accordance with this publication.

Referring to Figure 16, a top view of a measurement probe assembly 1671 in accordance with one or more aspects of the present disclosure is presented. The measuring probe assembly 1671 is essentially similar or identical to the measuring probe assembly 1571 shown in Figure 15, with the following possible exceptions. The measuring probe assembly 1671 may include an inner sealing element 1611 and an outer sealing element 1621, in which the inner sealing element 1611 may define a sample flow path 1613 and the outer sealing element 1621 may define a protective flow path 1623. The inner sealing element 1611 and the outer sealing element 1621 may have an elongated shape . The sample flow path 1613 and/or the protective flow path 1623 can also have an elongated shape. The inner seal member 1611 may be located on an inner support 1631 and the outer seal member 1621 may be located on top of an outer support 1633. The sample flow path 1631 may have an inlet 1617, in which a flow line may be fluidly connected to the inlet 1617. Compared to the inlet 1517 in figure 15, inlet 1617 may have a more substantial oval shape. This may enable the sample flow path 1613 to have a larger filtration or flow area, compared to the sample flow path 1513 in Figure 15.

According to one or more aspects of the present disclosure, an outer sealing member may have a length of about 25.4 cm (10 inches) and a width of about 12.7 cm (5 inches), and an inner sealing member may have a length of approximately 20.6 cm (8.1 inches) and a width of approximately 7.1 cm (2.8 inches). As such, a protective flow path may have a length of approximately 22.4 cm (8.8 inches) and a width of approximately 9.2 cm (3.6 inches), and a test flow path may have a length of approximately 17.3 cm (6.8 inches) and a width of approximately 4.0 cm (1.6 inches). This enables the measuring probe assembly to have an area of approximately 127.7 cm2 (19.8 in<2>) available for the sample flow path and the guard flow path, an area of approximately 69.0 cm2 (10.7 in<2>) available for the test flow path and a production rate (e.g. flow rate) ratio of approximately 1 to 2.1 between the test flow path and the protection flow path. These dimensions can be applied to the device as shown in one or more figures 2-16. While other dimensions are also within the scope of the present disclosure, the inventors have shown experimentally that such a production rate ratio provides unexpected and significant improvements over prior art.

Referring to Figure 17, illustrated is a schematic representation of a well installation 1700 having a drilling rig 1710 with a drill rod 1712 suspended therefrom in accordance with one or more aspects of the present disclosure. The well installation 1700 as shown, or a similar one, can be used within onshore and/or offshore areas. In this embodiment, a wellbore 1714 may be formed in a subterranean formation F, such as by using rotary drilling or any other method known in the art. As such, one or more of the embodiments in accordance with the present disclosure may be used within a well installation similar to that shown in Figure 17 (further discussed below). Those of ordinary skill in the art will understand that this disclosure can be used within other well installations or drilling operations, such as within directional drilling equipment, without deviating from the scope of this disclosure.

The drill rod 1712 can be suspended from the drill rig 1710 into the well drill 1714. The drill rod 1712 can be included in a bottom hole assembly 1718 and a drill bit 1716, in which drill bit 1716 can be located on one end of the drill rod 1712. On the surface of the drilling installation 1700, the drill rig 1710 can be located above the well drill 1714, and the drilling rig 1710 may include a rotary table 1720, a rotary pipe 1722, a movable block or hook 1724, and may additionally include a flushing head 1726. The flushing head 1726 may be suspended from the drilling rig 1710 through the hook 1724, and the rotary pipe 1722 may be connected to the flush head 1726 so that the rotation tube 1722 can rotate with respect to the flush head.

An upper end of the drill rod 1712 can be connected to the rotary pipe 1722, such as with threaded connections of the drill rod 1712 to the rotary pipe 1722, and the rotary table 1720 can rotate the rotary pipe 1722, thereby rotating the drill rod 1712 connected thereto. As such, the drill rod 1712 may be capable of rotating with respect to the hook 1724. However, those of ordinary skill in the art will appreciate that although a rotary drilling system is shown in Figure 17, other drilling systems may be used without departing from the scope of the present invention. publication. For example, a top drive (also known as a "power wheel") system may be used without departing from the scope of this disclosure. In such a top drive system, the hook 1724, flywheel 1726 and rotary tube 1722 are replaced by a drive motor (electric or hydraulic), which can apply rotational force and shaft weight directly to the drill rod 1712.

The well installation 1700 may include drilling fluids 1728 (also known as "drilling mud"), stored in a shaft 1730. The shaft 1730 may be shaped adjacent the well installation 1700, as shown, in which a pump 1732 may be used to pump the drilling mud 1728 into the borehole 1714 The pump 1732 can pump and deliver the drilling mud 1728 into and through a port in the rotary pipe 1726, thereby enabling the drilling mud 1728 to flow into and down through the drill rod 1712, in a flow direction for the drilling mud 1728 as indicated generally by the directional arrow 1734. This drilling mud 1728 may then leave the drill rod 1712 through one or more of the ports located within and/or fluidly connected to the drill rod 1712. For example, the drilling mud 1728 may leave the drill rod 1712 through one or more of the ports formed within the drill bit 1716.

As such, the drilling mud 1728 can flow back upward, through the wellbore 1714, such as through an annular volume 1736 formed between the outer drill rod 1712 and the inner wellbore 1714, where the direction of flow of the drilling mud 1728 is generally indicated by directional arrow 1738. When the drilling mud 1728 follows the flow pattern of directional arrows 1734 and 1738, the drilling mud 1728 may lubricate the drill rod 1712 and the drill bit 1716, and/or it may transport formation samples formed by the drill bit 1716 (or formed by any other drilling component located within the wellbore 1714) back to the surface of the well installation 1700. As such, this drilling mud may 1728 is filtered and cleaned and/or returned back to the shaft 1730 for recirculation within the wellbore 1714.

Although not shown, drill rod 1712 may include one or more stabilizing collars. A stabilizing collar may be located within and/or connected to the drill rod 1712, in which the stabilizing collar may be used to connect and apply a force against the wall of the wellbore 1714. This may enable the stabilizing collar to prevent the drill rod 1712 from deviating from the desired direction of the wellbore 1714. For example, during drilling, the drill rod 1712 can "rock" within the wellbore 1714, thereby enabling the drill rod 1712 to deviate from the desired direction of the wellbore 1714. This rocking can also hinder the drill rod 1712, components that are placed therein and the drill bit 1716 connected thereto. However, a stabilization collar can be used to minimize, if not completely overcome, the rocking motion of the drill rod 1712, thereby possibly increasing the efficiency of the drilling performed at the well installation 1700 and/or increasing the overall life of the components at the well installation 1700.

As discussed above, the drill rod 1712 may include a wellbore assembly 1718, such as by having the wellbore assembly 1718 positioned adjacent the drill bit 1716 within the drill rod 1712. The wellbore assembly 1718 may include one or more components included therein, such as components to measure, process and/or store information. The wellbore assembly 1718 may include components to communicate and/or transmit information to the surface of the well installation.

As such, as shown in Figure 17, the wellbore assembly 1718 may include one or more measurement-while-drilling ("LWD") tools 1740 and/or one or more measurement-while-drilling ("MWD") tools 1742. The wellbore assembly 1718 can also include a steering-while-drilling system { e.g. a rotatable system) and motor 1744, in which the rotatable system and motor 1744 may be connected to the drill bit 1716.

The LWD tool 1740 shown in Figure 17 may include a thick-walled capsule, commonly referred to as a drill collar, and may include one or more of a number of measuring tools known in the art. Thus, the LWD tool 1740 may be capable of measuring, processing and/or storing information therein, as well as having the capacity to communicate with equipment located on the surface of the well installation 1700 .

The MWD tool 1742 may also include a capsule (eg, a drill collar) and may include one or more of a number of measuring tools known in the art, such as tools used to measure the characteristics of the drill rod 1712 and/or drill bit 1716. MWD -the tool 1742 may also include an apparatus for generating and distributing power within the wellbore assembly 1718. For example, a mud turbine generator, driven by liquid drilling mud therethrough, may be located within the MWD tool 1742. Alternatively, other drive sources and/or power storage sources (e.g. . a battery) is placed inside the MWD tool 1742 to supply power inside the wellbore assembly 1718. As such, the MWD tool 1742 may include one or more of the following measurement tools, a weight-on-piece measurement unit, a force measurement unit, a vibration measurement unit, a shock measurement unit, a piece slip measurement unit, a direction measurement unit, an angle measurement unit and/or other equipment used in MWD tools, as known in the art.

In accordance with one or more aspects of the present disclosure, the LWD tool 1740 may include a carrier module with a sample chamber for imparting injected fluid into the wellbore 1714. A plunger may be located within the sample chamber, the plunger constituting a first chamber and a second chamber within the sample chamber. The sample chamber may comprise a first liquid port connected to the first chamber and a second liquid port connected to the second chamber. The carrier module may comprise a flow regulator, fluidly connected to at least one of the first flow ports and the second flow port. The LWD tool 1740 may be used to inject fluid from the sample chamber into the formation F as described herein.

With reference to Figure 18, a schematic representation of a tool 1800 is illustrated in accordance with one or more aspects of the present disclosure. The tool 1800 may be connected to and/or included within a drill rod 1802, in which the tool 1800 may be located within a wellbore 1804, formed within a subterranean formation F. As such, the tool 1800 may be included in and used within a wellbore assembly, which described above.

In particular, the tool 1800 may include a sample-while-boring ("SWD") tool, such as described in US Patent No. 7,114,562, filed November 24, 2003, entitled "Apparatus and Method for Acquiring Information While Drilling", and incorporated in its entirety herein by reference. As such, the tool 1800 may include a measurement probe 1810 to hydraulically establish communication with the subterranean formation F and draw formation fluid 1812 into the tool 1800 .

The tool 1800 may also include a stabilization blade 1814 and/or one or more pistons 1816. As such, the measurement probe 1810 may be located on the stabilization blade 1814 and extend therefrom to couple with the wall of the wellbore 1804. The pistons, if present, may also extend from the tool 1800 to support the measuring probe 1810 in the connection with the wall of the wellbore 1804. Alternatively, however, the measuring probe 1810 does not need to be connected to the wall of the wellbore 1804 when liquid is drawn up.

As such, fluid 1812 drawn into the tool 1800 may be measured to determine one or more parameters of the subterranean formation F, such as pressure and/or the pretest parameters of the subterranean formation F. In addition, the tool 1800 may include one or more devices such as such as sample chambers or sample bottles, which can be used to collect formation fluid samples. These formation fluid samples may be retrieved to the surface by the tool 1800. Alternatively, rather than collecting formation fluid samples, the formation fluid 1812 received inside the tool 1800 may be circulated back out and into the subsurface formation F and/or the wellbore 1804. As such, a pumping system may is included inside the tool 1800 to pump the formation fluid 1812 that circulates inside the tool 1800. For example, the pumping system can be used to pump the formation fluid 1812 from the measuring probe 1810 to the sample bottles and/or back to the formation F.

According to one or more aspects of the present disclosure, the tool 1800 may be used to inject fluid through the measuring probe 1810 and into the formation F, as described herein. As such, the tool 1800 may comprise a carrier module with a sample chamber for conveying injected fluid into the wellbore 1804. A piston may be located in the sample chamber, where the piston constitutes a first chamber and a second chamber within the sample chamber. The sample chamber may comprise a first liquid port connected to the first chamber and a second liquid port connected to the second chamber. The carrier module may comprise a flow regulator, fluidly connected to at least one of the first flow ports and the second flow port.

With reference to Figure 19, a schematic representation of a tool 1900 is presented in accordance with one or more aspects of the present disclosure. The tool 1900 may be connected to and/or included within a wellbore assembly, in which the tool 1900 may be located within a wellbore 1904 formed within a subterranean formation F. The tool 1900 may be a pressure LWD tool used to measure one or more well pressures , including annulus pressure, formation pressure and cavity pressure before, during and/or after a drilling operation. Those of ordinary skill in the art will appreciate that pressure tools other than LWD tools may be used in one or more respects, such as those described in US Patent No. 6,986,282, filed February 18, 2004, entitled "Method and Apparatus for Determining Downhole Pressures During a Drilling Operation" and hereby incorporated herein by reference. As shown, the tool 1900 may be formed as a modified stabilization collar 1910, similar to the stabilization collar described above, and may have a passage 1912 formed therethrough for drilling mud. The flow of drilling mud through the tool 1900 can create an internal pressure Ti and the outside of the tool 1900 can be exposed to an annulus pressure Ta of the surrounding wellbore 1904 and formation F. A differential pressure Tg formed between the internal pressure Ti and the annulus pressure Ta can then be used to to activate one or more pressure units 1916 that may be included in the tool 1900.

The tool 1900 may include two pressure measurement units 1916A and 1916B, which may be located on stabilization blade 1918 formed on the stabilization collar 1910. The pressure measurement equipment 1916A may be used to measure annulus pressure Ta in the wellbore 1904 and/or may be used to measure the pressure in the formation F when placed in contact with a wall 1906 to the wellbore 1904. As shown in Figure 19, the pressure measurement equipment 1916A is not in contact with the wellbore wall 1906, thereby making it possible for the pressure measurement equipment 1916A to measure the annulus pressure Ta, if desired. When the pressure measurement equipment 1916A is moved into contact with the wellbore wall 1906, the pressure measurement equipment 1916A can be used to measure the cavity pressure in the formation F.

Also as shown in Figure 19, the pressure measurement equipment 1916B may be extendable from the stabilization blade 1918, such as by using a hydraulic control located within the tool 1900. When extended from the stabilization blade 1918, the pressure measurement equipment 1916B may establish a sealing connection with the wall 1906 of the wellbore 1904 and/or a mud cake 1908 in the wellbore 1904. This may also enable the pressure measurement equipment 1916B to take measurements of the formation F. Other controls and circuits, not shown, may be used to connect the pressure measurement equipment 1916 and/or other components of the tool 1900 to a processor and/or control. The processor and/or control can then be used to communicate the measurements from the tool 1900 to other tools within a wellbore assembly or to the surface of a well installation. As such, a pumping system may be included in the tool 1900, such as including the pumping system within one or more of the pressure units 1916 for actuation and/or movement of the pressure equipment 1916.

Referring to Figure 20, a side view of a tool 2000 is presented in accordance with one or more aspects of the present disclosure. The tool 2000 may be a "well cable" tool, in which the tool 2000 may be suspended within a wellbore 2004 formed within a subterranean formation F. As such, the tool 2000 may be suspended from one end of a multiconductor cable 2006 located at the surface of the formation F, such as by having the multi-conductor cable 2006 wrapped around a winch (not shown), placed on the surface of formation F. The multi-conductor cable 2006 is then connected to the tool 2000 with electronics and a processing system 2008 placed on the surface.

The tool 2000 may have an elongated body 2010 that includes a formation tester 2012 positioned therein. The formation tester 2012 may include an extendable measuring probe 2014 and an extendable anchor element 2016, in which the measuring probe 2014 and the anchor element 2016 may be located on opposite sides of the body 2010. One or more other components 2018, such as a measuring unit, may also be included in the tool 2000.

The measuring probe 2014 may be included in the tool 200 so that the measuring probe 2014 can be extended from the body 2010 and then selectively seal off and/or isolate selected parts of the wall of the wellbore 2004. This may enable the measuring probe 2014 to establish pressure and/or fluid communication with the formation F to retrieve fluid samples from the formation F. The tool 2000 can also include a fluid analysis tester 2020 which is in fluid communication with the measuring probe 2014, thereby enabling fluid analysis tests 2020 to measure one or more properties of the fluid. The liquid from the measuring probe 2014 can also be sent to one or more sample chambers or bottles 2022, which can receive and retain liquids taken up from the formation F for later testing after being received at the surface. The liquid from measuring probe 2014 can also be sent back out into the wellbore 2004 or the formation F.

Referring to Figure 21, a side view of another tool 2100 is illustrated in accordance with one or more aspects of the present disclosure. The tool 2100 can be suspended within a wellbore 2104 formed within a subterranean formation F using a multi-conductor cable 2106. The multi-conductor cable 2106 can be supported by a drilling rig 2102. The tool 2100 can include one or more packings 2108 that can be configured to be inflated, thereby selectively sealing a portion of the wellbore 2104 for the tool 2100. To test the formation F, the tool 2100 may include one or more measuring probes 2110 and the tool 2100 may also include one or more outlets 2112 that may be used to inject fluids within the sealed portion established of the seals 2108 between the tool 2100 and the formation F.

According to this, an apparatus as described in figures 2-16 can be used in well tools as described in figures 17-21 or any other well cable or under-drilling well tool within the scope of this publication.

In light of all of the foregoing and the figures, those skilled in the art can readily appreciate that the present disclosure introduces an apparatus comprising: a tool body configured for placement within a well, wherein the well extends into a subterranean formation, and a measuring probe assembly movably attached thereto to the tool body, and the measuring probe assembly comprises: an inner sealing element and an outer sealing element, wherein at least one of the inner sealing elements and the outer sealing element comprises an elongated shape. The apparatus may further comprise a sample flow inlet configured to receive liquid from within the inner sealing element, and a protective flow inlet, configured to receive liquids from within the inner sealing element and the outer sealing element. The sample flow inlet may comprise a piston with a filter positioned adjacent the piston. The apparatus can further comprise a first flow line, fluidly connected to the sample flow inlet, and a second flow line fluidly connected to the protective flow inlet. The measuring probe assembly can be movably attached to the tool body using at least one control unit. The at least one control unit may comprise at least one of the hydraulic control units, a pneumatic control unit, a mechanical control unit and an electrical control unit. The at least one control unit may comprise a piston. The inner sealing member can be configured to move with respect to the outer sealing member. The inner sealing element can be placed in an inner support, and the outer sealing element can be placed in an outer support. The sample flow inlet can be formed in the inner support, and in which a protective flow inlet will be formed in the outer support. The apparatus may further comprise first a control unit connected to the inner support and a second control unit connected to the outer support, wherein the inner support may be configured to move with respect to the outer support. The first control unit may comprise a first piston, and the second control unit may comprise a second piston. The apparatus can further comprise a gasket attached to the tool body, in which at least part of the measuring probe assembly can be placed on top of the gasket. The inner sealing element may be placed on an inner support attached to the gasket, and an outer sealing element may be placed on the gasket. The package may comprise an inflatable package. This disclosure also introduces a method comprising: providing a tool body, the tool body configured for placement in a well, the wellbore extended into a subterranean formation, and movably attaching a probe assembly to the tool body, the probe assembly comprising an inner seal member and an outer seal member, wherein at least one of the inner sealing elements and the outer sealing element comprises an elongated shape. The method may further comprise providing a sample flow inlet within the measuring probe assembly, wherein the sample flow inlet is configured to receive liquid from within the inner sealing element and providing a protective flow inlet within the measuring probe assembly, wherein the protective flow inlet is configured to receive liquid from between within the inner sealing element and the outer sealing element. The method can further comprise fluid connection of a first flow line to the sample flow inlet, and a fluid connection to a second flow line to the protective flow inlet. The measuring probe assembly can be movably attached to the tool body using at least one control unit. The at least one control unit may comprise a piston. The inner sealing member can be configured to move with respect to the outer sealing member. The method can further comprise placing the inner sealing element on an inner support, and placing the outer sealing element on an outer support. The method can further comprise connecting a first control unit to the inner support, and connecting a second control unit to the outer support. The method can further comprise placing the inner sealing element on a support, and placing the outer sealing element on a gasket. This disclosure also introduces an apparatus comprising: a tool body configured for placement in a wellbore extended into a subterranean formation, an inflatable packing coupled to the tool body, and a probe assembly coupled to the tool body and comprising an inner seal member and an outer seal member, wherein at least one of the inner sealing elements and the outer sealing element comprises an oblong shape, and in which at least a part of the measuring probe assembly is placed on the inflatable gasket. The inner sealing element can be placed on an inner support attached to the inflatable package, and the outer sealing element can be placed directly on the inflatable package. The apparatus may further comprise: a sample flow inlet configured to receive liquid from within the inner sealing element, and a protective flow inlet configured to receive liquids from between the inner sealing element and the outer sealing element. The sample flow inlet may comprise a piston with a filter positioned adjacent the piston. The apparatus can further comprise: a first flow line, fluidly connected to the sample flow inlet, and a second flow line fluidly connected to the protective flow inlet. The tool body may be connected to a well tool configured for communication within the wellbore via a well cable or a drill bit.

This disclosure also introduces a method comprising: placing a well tool within a wellbore extended into a subterranean formation, wherein the well tool comprises: an inflatable pack coupled to a tool body and a probe assembly coupled to the tool body and comprising an inner seal member and an outer seal member , in which at least one of the inner sealing elements and the outer sealing element comprises an elongated shape, in which the inner sealing element at least partially defines the sample inlet, in which the inner and outer sealing elements together at least partially define a protective inlet, and in which at least part of the measuring probe assembly is placed on the inflatable packing, thus establishing fluid communication between a sidewall of the wellbore and the inner and outer sealing elements of the probe assembly, by inflating the inflatable packing and drawing formation fluid from the formation into the well tool through ver the ne and sample inlets. The inner sealing element can be placed on an inner support attached to the inflatable package, and the outer sealing element can be placed directly on the inflatable package. The sample inlet may comprise a piston with a filter placed adjacent to the piston and the method may further comprise controlling the piston to empty the filter. Placement of the well tool inside the well drill may include placing the well tool, via a well cable or drill rod.

This disclosure also introduces an apparatus comprising: a tool body configured for placement within a wellbore extending into a subterranean formation, and a probe assembly coupled to the tool body and comprising an inner seal member and an outer seal member, wherein the outer seal member has a length of about 25.4 cm (10 inches) and a width of about 12.7 cm (5 inches), and wherein the inner sealing member has a length of about 20.6 cm (8.1 inches) and a width of about 7.1 cm (2.8 in). A protective flow path defined between the inner and outer sealing members may have a length of about 22.4 cm (8.8 inches) and a width of about 9.2 cm (3.6 inches). A protective flow path defined between the inner and outer sealing members may have a length of about 17.3 cm (6.8 inches) and a width of about 4.0 cm (1.6 inches). The test flow path and the protective flow path together can have an area of approximately 127.7 cm<2> (19.8 in<2>). The sample flow path may have an area of approximately 69.9 cm (10.7 in). The measuring probe assembly may have a production rate ratio of approximately 1 to 2.1 between the sample flow path and the protection flow path. The apparatus may further comprise an inflatable seal connected to the tool body, in which the inner sealing element is placed on an inner support attached to the inflatable seal and in which the outer sealing element is placed directly on the inflatable seal. The tool body can be connected to a well tool configured for transmission within the wellbore via either a well cable or a drill bit.

The foregoing outlines functions of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art will appreciate that they can immediately use the present disclosure as a basis for designing and modifying other processes and structures to accomplish the same tasks and/or achieve the same benefits of the embodiments introduced herein. Those who know the subject must also be able to understand that such equivalent constructions do not deviate from the spirit and scope of this publication and that they can therefore carry out various changes, replacements and conversions without deviating from the spirit and scope of this publication. The summary at the end of this publication is presented in accordance with C.F.R. § 1.72 (b) to enable the reader to make a quick assessment of the technical nature of this disclosure. It is presented on the understanding that it will not be used to interpret or limit the scope or meaning of the requirements.

Claims (20)

1. Apparatus comprising: a tool body configured for placement within a wellbore extending into a subterranean formation. an inflatable gasket connected to the tool body, and a measuring probe assembly connected to the tool body and comprising an inner sealing element and an outer sealing element, in which at least one of the inner sealing elements and the outer sealing element comprises an elongated shape, and in which at least part of the measuring probe assembly is placed on the inflatable package. 2. The apparatus of claim 1 wherein an inner sealing member is placed on an inner support attached to the inflatable package, and wherein the outer sealing member is placed directly on the inflatable package. 3. The apparatus of claim 1 further comprising: a sample flow inlet configured to receive fluid from within the inner sealing member, and a protective flow inlet configured to receive fluid from between the inner sealing member and the outer sealing member. 4. The apparatus of claim 3 wherein the sample flow inlet comprises a piston having a filter positioned adjacent the piston. 5. The apparatus in claim 3 further comprising: a first flow line fluidly connected to the sample flow inlet, and a second flow line fluidly connected to the protective flow inlet. 6. The apparatus of claim 1 wherein the tool body is connected to a well tool configured for transmission inside the wellbore via a well cable. 7. The apparatus of claim 1 wherein the tool body is connected to a well tool configured for transmission inside the wellbore via a drill rod. 8. Method comprising: placing a well tool within a wellbore extended into an underground formation, wherein the well tool comprises: an inflatable pack connected to a tool body, and a measuring probe assembly connected to the tool body and comprising an inner seal member and an outer seal member, wherein at least one of the inner sealing elements and the outer sealing element comprises an elongated shape, in which the inner sealing element at least partially defines a sample inlet, in which the inner and outer sealing elements at least partially define the protective flow inlet, and in which at least a part of the measuring probe assembly is placed on the inflatable the packing, establish fluid communication between a side wall in the wellbore and the inner and outer sealing elements in the probe assembly by inflating the inflatable packing, and draw formation fluid from the formation into the well tool through the protection and test inlets. 9. The method of claim 8 wherein an inner sealing member is placed on an inner support attached to the inflatable package and wherein the outer sealing member is placed directly on the inflatable package. 10. The method in claim 8 wherein the sample inlet comprises a piston with a filter positioned adjacent to the piston, and wherein the method further comprises controlling the piston to empty the filter. 11. The method in claim 8 in which placing the well tool inside the well drill comprises placing the well tool via a well cable. 12. The method in claim 8 in which placement of the well tool inside the well drill includes placement of the well tool via a drill rod. 13. Apparatus comprising: a tool body configured for placement within a wellbore extending into a subterranean formation, and a probe assembly coupled to the tool body and comprising an inner seal member and an outer seal member, wherein the outer seal member has a length of about 25, 4 cm (10 inches) and a width of approximately 12.7 cm (5 inches), and wherein the inner sealing member has a length of approximately 20.6 cm (8.1 inches) and a width of approximately 7.1 cm ( 2.8 inches). 14. The apparatus of claim 13 wherein a protective flow path defined between the inner and outer sealing members has a length of about 22.4 cm (8.8 inches) and a width of about 9.2 cm (3.6 inches). 15. The apparatus of claim 14 wherein a sample flow path defined between the inner and outer sealing members has a length of about 17.3 cm (6.8 inches) and a width of about 4.0 cm (1.6 inches). 16. The apparatus of claim 15 wherein the test flow path and the protective flow path together may have an area of approximately 127.7 cm<2> (19.8 inches<2>). 17. The apparatus of claim 16 wherein the sample flow path has an area of approximately 69.0 cm<2> (10.7 inches<2>). 18. The apparatus of claim 17 wherein the measuring probe assembly has a production rate ratio of approximately 1 to 2.1 between the test flow path and the protection flow path. 19. The apparatus of claim 13 further comprising an inflatable seal connected to the tool body, wherein the inner sealing member is placed on an inner support attached to the inflatable seal and wherein the outer sealing member is placed directly on the inflatable seal. 20. The apparatus of claim 13 wherein the tool body is connected to a well tool configured for placement inside the wellbore via either a well cable or a drill rod.